1. Technical Field of the Invention
The present invention generally relates to sulfur recovery processes and to apparatus for removing sulfur from H2S-containing gas streams and producing elemental sulfur. More particularly, the invention relates to processes that employ an H2S catalytic partial oxidation stage followed by a SO2 catalytic partial reduction stage, and to apparatus for carrying out such processes.
2. Description of the Related Art
Sulfur removal from H2S-containing gas streams is a field of endeavor that is receiving a great deal of attention today, particularly in the petroleum industry. Considerable quantities of H2S are created from the refining of petroleum in processes such as crude oil hydrodesulfurization, gasification of coal and desulfurization of natural gas. Removal of H2S from H2S-containing gases is a major focus of current research because utilization of the enormous supply of natural gas existing in underground reservoirs all over the world is hindered due to the presence of naturally-occurring H2S along with the methane and other light hydrocarbons that make up natural gas. Some natural gas formations contain only a relatively small concentration of H2S, yet even those types of natural gas wells typically remain shut-in today because the cost of removal of the H2S using existing methods and apparatus exceeds the market value of the gas. A further deterrent to full utilization of H2S-containing natural gas resources is the corrosive effect of the H2S component of liquefied natural gas on the transportation pipes and storage vessels that are needed to bring the H2S-containing natural gas from remote locations to existing sulfur treatment plants.
The removal of sulfur from naturally occurring and industrially produced H2S-containing gas streams is necessitated by the high demand for clean energy sources, and by increasingly stringent clean air standards for industrial emissions that restrict or prohibit the release of H2S into the environment due to its high toxicity and foul odor. Since the amount of sulfur recovered from an industrial H2S-containing stream may be quite large, the elemental sulfur product can have significant commercial value.
Many processes have been described for accomplishing the removal and recovery of sulfur from H2S-containing gases. The sulfur plants in common use today employ a modification of a process that was developed over 200 years ago in which H2S was reacted over a catalyst with air (oxygen) to form elemental sulfur and water (the Claus process). Sulfur recovery was low and the highly exothermic reaction was difficult to control. Modified Claus processes were introduced to overcome the deficiencies of the original Claus process, and today are generally referred to as “Claus Processes.” In a conventional Claus process, the H2S-containing gas stream is contacted with air or a mixture of oxygen and air in a flame. One third (⅓) of the H2S is burned according to the equation:H2S+ 3/2O2→SO2+H2O  (1)The remaining ⅔ of the H2S is converted to sulfur via the (Claus) reaction:2H2S+SO2⇄3/xSx+2H2O  (2)
(x=2, 6, or 8 depending on temperature and pressure). The gases are cooled in a fire tube boiler after the burner. Typically, this step converts 55 to 70% of the H2S to elemental sulfur. The equilibrium of the reaction of equation (2), referred to as the “Claus reaction,” limits the conversion. To improve the yield, elemental sulfur is condensed from the gas stream. After sulfur condensation and separation from the liquid sulfur, the unreacted gases are heated to the desired temperature, passed over a catalyst that promotes the Claus reaction, and cooled again to condense and separate the sulfur. Generally, two to three stages of Claus reheater, reactor, and condenser stages are employed. Over the years, most of the modifications to the Claus process have involved improvement of burner design, use of more active and durable catalysts, and use of different types of reheaters. Anywhere from 90 to 98% of the H2S fed to the unit is recovered as elemental sulfur. Any remaining H2S, SO2, sulfur, or other sulfur compounds in the Claus plant effluent are either incinerated to SO2 and discharged to the atmosphere, or incinerated to SO2 and absorbed by chemical reaction, or converted by hydrogen to H2S and recycled or absorbed by an alkanolamine solution. This is accomplished by various Claus “tail gas” treatment units, which improve the efficiency of sulfur removal from the gas discharged to the atmosphere.
Claus processes are generally efficient for processing large quantities of gases containing a high concentration (i.e., >40 vol. %) H2S in plants producing more than 100,000 tons of sulfur per year. The Claus-type processes are not suitable for use in cleaning up hydrogen or light hydrocarbon gases (such as natural gas) that contain H2S, however. Not only is the hydrocarbon content lost in the initial thermal combustion step of the Claus process, but carbon, carbonyl sulfide and carbon disulfide byproducts cause catalyst fouling and dark sulfur. Moreover, carbonyl sulfide is difficult to convert to elemental sulfur. In the past, others have usually addressed the problem of purifying hydrogen sulfide contaminated hydrogen or gaseous light hydrocarbon resources by employing an initial amine extraction technique.
Typically, alkanolamine absorption of the H2S component of a gas stream is performed, followed by H2S regeneration and conventional multistage Claus sulfur recovery, usually including tail gas treatments. According to conventional industrial practices, a hydrocarbon or hydrogen containing gas stream containing a low concentration of H2S is contacted with a water solution containing an alkanolamine. Alkanolamines commonly employed in the industry are monoethanolamine (MEA), diethanolamine (DEA), methyldiethanol amine (MDEA), diglycolamine (DGA), and diisopropanolamine (DIPA). These are basic nitrogen compounds. The basic alkanolamine reacts with the H2S and other gases that form acids when dissolved in water to form alkanolamine salts, according to the following generic reaction:Alkanolamine+Acid Gas=Protonated alkanolamine+weak acid anionWhen ethanolamine is the basic alkanolamine, the reaction is:H2N—CH2CH2OH+H2S→+NH3—CH2CH2OH+HS−  (3)The hydrogen or hydrocarbon gas, substantially freed of H2S, is recovered and may be used as fuel or routed to another system for processing. After absorbing the H2S from the gas, the alkanolamine solution is transported, heated, and placed in a stripping tower. Steam generated from boiling the alkanolamine solution at the bottom of the stripping tower, lowers the vapor pressure of the acid gas above the solution, reversing the equilibrium of the acid gas/alkanolamine reaction described above. The acid gases leaving the stripper are cooled to condense most of the remaining steam. The acid gas stream then goes to a Claus sulfur recovery plant, as described above.
The major problem with the Claus process is the inherent equilibrium constraint of the Claus reaction caused by the necessity of generating the SO2 intermediate. Others have addressed this problem by attempting to directly oxidize H2S to sulfur using alumina based catalysts and low temperature operating conditions. SUPERCLAUS™ processes such as the STRETFORD™ process are examples of low temperature direct oxidation methods. Typically, these processes are catalytic oxidations operating at temperatures below about 454° C., so that the reaction can be contained in ordinary carbon steel vessels. Usually these catalytic oxidation processes are limited to Claus tail gas operations or sulfur recovery from streams that have very low H2S content (i.e., about 1–3%). One reason for this limited use is that the heat evolved from the oxidation of a concentrated stream of H2S would drive the reaction temperatures well above 454° C. requiring refractory lined vessels such as the conventional Claus thermal reactor. Low concentration H2S streams will not produce enough energy release from oxidation to sustain a flame as in a thermal reactor stage. The existing catalytic oxidation technologies are thus limited to low concentration H2S-containing streams using non-refractory lined vessels. Existing processes are also limited in the amount of sulfur that can be handled because the heat transfer equipment needed to remove the heat of reaction becomes extremely large due to the low temperature differential between the process and the coolant streams.
Some techniques for improving efficiency of sulfur removal that have been described in the literature for purifying hydrogen sulfide contaminated hydrogen or gaseous light hydrocarbon resources include: 1) adsorbing sulfur cooled below the freezing point on a solid material followed by releasing the trapped sulfur as a liquid by heating the solid adsorbent; 2) selectively oxidizing the remaining H2S to sulfur using air; and 3) selectively oxidizing the H2S to sulfur employing aqueous redox chemistry utilizing chelated iron salts or nitrite salts. According to the latter methods, the H2S-contaminated hydrogen or hydrocarbon stream is contacted directly with the redox reagent such as chelated iron (III) ions. The iron (III) is reduced to iron (II) ion while the H2S is converted to elemental sulfur. The sulfur in liquid form is separated from the solution. These types of desulfurization units have been shown to be practical when the amount of sulfur to be removed from the stream is below 5 long tons per day. The SULFUROX™ and LO-CAT™ processes are examples of this type of H2S conversion process. Some of these direct oxidation processes use a liquid medium to carry out the oxidation or to act as a carrier for the oxidizer. These processes are also limited in the amount of sulfur recovered due to the heat removal constraints at low temperatures and the need to maintain low temperatures to keep the liquid from boiling. For at least these reasons, existing direct oxidation processes have not proved to be viable substitutes for the Claus process in most industrial applications.
U.S. Pat. No. 5,700,440; U.S. Pat. No. 5,807,410 and U.S. Pat. No. 5,897,850 describe some of the limitations of existing tail gas treatment (TGT) processes and the difficulty of meeting increasingly stringent government requirements for desulfurization efficiency in the industry. J. B. Hyne (Oil and Gas Journal Aug. 28, 1972: 64:78) gives an overview of available processes for effluent gas stream desulfurization and discusses economical and environmental considerations. R. H. Hass et al. (Hydrocarbon Processing May 1981:104–107) describe the BSR/Selectox™ process for conversion of residual sulfur in Claus tail gas or for pre-Claus treatment of a gas stream. K-T Li et al. (Ind. Eng. Chem. Res. 36:1480–1484 (1997)) describe the SuperClaus™ TGT system which uses vanadium antimonate catalysts to catalyze the selective oxidation of hydrogen sulfide to elemental sulfur.
U.S. Pat. No. 5,603,913 describes several oxide catalysts that have been suggested for catalyzing the reactionH2S+½O2→½S2+H2O  (4)Because reaction (4) is not a thermodynamically reversible reaction, direct oxidation techniques offer potentially higher levels of conversion than is typically obtainable with thermal and catalytic oxidation of H2S. As mentioned above, conventional direct oxidation methods are applicable to sour gas streams containing relatively small amounts of H2S and large amounts of hydrocarbons, but are not particularly well suited for handling more concentrated acid gas streams from refineries. For this reason direct oxidation methods have been generally limited to use as tail gas treatments only, and have not found general industrial applicability for first stage sulfur removal systems from gases containing large quantities of H2S.
U.S. Pat. No. 6,372,193 (Ledoux et al.) describes a process for catalytically oxidizing a gas stream containing a low concentration (up to 25 vol. %) H2S directly to sulfur over a catalytically active phase carried on a silicon carbide-based support. The catalytically active phase is an oxysulfide of Fe, Cu, Ni, Co, Cr, Mo or W.
Z. R. Ismagilov et al. (React. Kinet. Catal. Lett. (1995) 55:489–499) suggest that monolith catalysts containing oxides of Co, V, Fe, Cr, Mn or Al have activity for catalytically converting the H2S in natural gas to sulfur in a first oxidation stage. The reaction conditions include a spherical particulate vanadium catalyst in a fluid bed reactor operating at 250–300° C., O2:H2S=0.5–1.1 and tc=0.5–0.8 s. Under such conditions H2S conversion and process selectivity of 99% is reported.
U.S. Pat. No. 4,886,649 (Ismagilov, et al.) describes a two stage direct oxidation process employing fluidized catalyst beds containing MgCrO4 and Al2O3, or V2O5 and Al2O3. According to that method, oxygen is supplied to the first oxidation stage in an amount of 100–110% of the stoichiometric amount necessary for oxidation of H2S to elemental sulfur. The range of treatable H2S containing gases is extended to gases containing about 30–50 vol. % H2S. The granular catalyst in a fluidized bed with a cooling coil or jacket, allows temperature uniformity of the catalyst bed. A maximum temperature level of 250–350° C. is desired in order to avoid forming products of coking and cracking of hydrocarbon components of the feed gas. In a second stage the unreacted H2S and oxygen from the first stage are reacted at 140–155° C. in the presence of a catalyst to form elemental sulfur.
U.S. Pat. No. 5,242,673 (Flytzani-Stephanopoulos et al.) describes a process for the direct recovery of elemental sulfur from the SO2 in an off-gas stream using CO and other reducing gases and certain cerium oxide-based catalysts. Alternatively, the feed is a combustion exhaust gas stream containing SO2. Certain metal oxide composite catalysts that are active for direct elemental sulfur recovery from a SO2-containing gas stream by reacting the SO2 with a reducing gas are described in U.S. Pat. No. 5,384,301 (Flytzani-Stephanopoulos et al.).
In a recent academic study (T. Zhu et al. Catalysis Today 50 (1999) 381–397) the conversion of SO2 to S0 by reduction over certain Cu-modified ceria-based catalysts using CO or CH4 was investigated. The processes described in that study were limited to relatively low temperatures (in the range of 450–750° C.) and low SO2 concentrations and do not contemplate H2S in the feed. It is stated that the use of catalysts for the direct conversion of SO2 to elemental sulfur has been explored many times in the past, and various reductants have been used, including CO, H2, CH4 and carbon. The overall reactions between SO2 and CO or CH4 to elemental sulfur product are described as:SO2+2CO→[S]+2CO2  (5)2SO2+CH4→CO2+2H2O+2[S]  (6)where [S] represents the various elemental sulfur forms (S2, S6, S8).
H. M. Lee and J. D. Han (Ind. Eng. Chem. Res. (2002) 41: 2623–2629) describe the catalytic reduction of sulfur dioxide in a combustion product gas stream using carbon monoxide to produce elemental sulfur by employing γ-Al2O3 supported sulfide catalysts of nickel and lanthanum-nickel.
Even though the Claus process still finds widespread industrial use today for recovering elemental sulfur from H2S that is generated in many industrial processes, such as petroleum refinery processes, and for reducing sulfur emissions from refineries, the Claus process is generally viewed as relatively costly for routine use on a commercial scale. As a result, the Claus process is currently performed mainly for the purpose of complying with government mandated environmental air quality standards. Most of the existing alternative desulfurization processes and systems must resort to use of a number of additional pre-treatments or post-treatment catalytic stages and tail gas-treatment units (TGTUs) in order to adequately clean the waste gas that is vented into the air sufficiently to meet current environmental regulations for venting of cleaned H2S-containing gas streams. Multi-stage tail gas treating units (TGTUs) typically convert the H2S that did not react in the Claus unit to elemental sulfur by (a) oxidizing completely to SO2, (b) reacting the SO2 with H2S in smaller concentrations to form S0, and (c) reacting very small concentrations of H2S with oxygen to form S0 at low temperatures using a catalyst. A number of TGTUs are usually needed to achieve the 99+% conversion of H2S to S0, and involves a large initial investment and appreciable maintenance costs.
Significant capital and maintenance costs are associated with conventional multi-stage treatment units. More economical and efficient ways of recovering elemental sulfur from an H2S-containing gas stream and of removing environmentally harmful H2S from industrial vent stack exhaust gases are needed. Conventional desulfurization operations are also not practical for use at small operations such as remote well sites or on natural gas producing offshore oil platforms.
The basic SPOC™ technology, as described in co-owned U.S. patent application Ser. No. 09/625,710, U.S. Pat. No. 6,579,510, U.S. patent application Ser. No. 10/024,679 (Publication No. 2002/0134706), and U.S. patent application Ser. No. 10/024,167 (Publication No. 2002/0131928), which are hereby incorporated herein by reference, provides an alternative to the conventional Claus process to handle H2S-containing fluid streams. U.S. Patent Application Publication Nos. 2002/0131928 and 2002/0134706 describe methods of selectively converting even high concentrations of hydrogen sulfide in H2S-containing gas streams to elemental sulfur via a short contact time catalytic partial oxidation process (SPOC™) that are more economic and efficient than a Claus type process. The process is carried out in a more compact system compared to a conventional Claus plant. Conversion of H2S to elemental sulfur by the SPOC™ process may be accompanied by the formation of some SO2 as a result of gas-phase reactions between H2S, S0 and O2 that occur both downstream from the catalyst zone and within the catalyst zone. This secondary production of SO2 is typically observed when higher than stoichiometric O2/H2S ratios are used to increase the H2S conversion. An apparatus and process that further improve the conversion of H2S to elemental sulfur would be valuable in the art, particularly for meeting stringent Federal environmental standards and the demands for cleaner industrial waste gas emissions as required by the Environmental Protection Agency.